TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from
to

Commission file number: 001-32395

ConocoPhillips

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of
incorporation or organization)

01-0562944

(I.R.S. Employer Identification No.)

600 North Dairy Ashford
Houston, TX 77079

(Address of principal executive offices) (Zip Code)

Registrants telephone number, including area code: 281-293-1000

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange

Title of each class

on which registered

Common Stock, $.01 Par Value

New York Stock Exchange

Preferred Share Purchase Rights Expiring June 30, 2012

New York Stock Exchange

6.65% Debentures due July 15, 2018

New York Stock Exchange

7% Debentures due 2029

New York Stock Exchange

9.375% Notes due 2011

New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act.

[x] Yes [ ] No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act.

[ ] Yes [x] No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for
such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.

[x] Yes [ ] No

Indicate by check mark whether the registrant has submitted electronically and posted on its
corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period
that the registrant was required to submit and post such files).

[x] Yes [ ] No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of the registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. [ ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated filer, or a smaller reporting company. See the definitions of large accelerated
filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.

Large accelerated filer [x]

Accelerated filer
[ ]

Non-accelerated
filer [ ]

Smaller
reporting company [ ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the
Act).

[ ] Yes [x] No

The aggregate market value of common stock held by non-affiliates of the registrant on June 30,
2009, the last business day of the registrants most recently completed second fiscal quarter,
based on the closing price on that date of $42.06, was $62.3 billion. The registrant, solely for
the purpose of this required presentation, had deemed its Board of Directors and grantor trusts to
be affiliates, and deducted their stockholdings of 811,943 and 39,808,419 shares, respectively, in
determining the aggregate market value.

The registrant had 1,486,838,088 shares of common stock outstanding at January 31, 2010.

Documents incorporated by reference:

Portions of the Proxy Statement for the Annual Meeting of Stockholders to be held on May 12, 2010
(Part III)

This Amendment No. 1 to the Annual Report on Form 10-K of ConocoPhillips for the year ended
December 31, 2009, is being filed for the purpose of providing separate audited financial
statements of OAO LUKOIL in accordance with Rule 3-09 of Regulation S-X. These audited financial
statements, which were not available prior to the due date for filing our 2009 Form 10-K, are
included in Item 15, Exhibits, Financial Statement Schedules. Otherwise, this amendment does not
update or modify in any way the financial position, results of operations, cash flows or the
disclosures in ConocoPhillips Annual Report on Form 10-K for the year ended December 31, 2009, and
does not reflect events occurring after the original filing date of
February 25, 2010.

Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES

(a)

1.

Financial Statements and Supplementary Data

The financial statements and supplementary information, as listed in the Index to Financial
Statements on page 70 of the original 2009 Form 10-K, were filed as part of the original
2009 Form 10-K filed on February 25, 2010.

2.

Financial Statement Schedules

Schedule IIValuation and Qualifying Accounts was filed on page 173 of the original 2009
Form 10-K filed on February 25, 2010. All other schedules are omitted because they are not
required, not significant, not applicable or the information is shown in another schedule,
the financial statements or the notes to consolidated financial statements.

The following information is included herein in this amended Form 10-K pursuant to Rule 3-09
of Regulation S-X:

OAO LUKOIL



Independent Auditors Report.



Consolidated Balance Sheets as of December 31, 2009 and 2008.



Consolidated Statements of Income for the years ended December 31, 2009, 2008
and 2007.



Consolidated Statements of Stockholders Equity and Comprehensive Income for the
years ended December 31, 2009, 2008 and 2007.



Consolidated Statements of Cash Flows for the years ended December 31, 2009,
2008 and 2007.



Notes to Consolidated Financial Statements.



Supplementary Information on Oil and Gas Exploration and Production Activities
(Unaudited).

3.

Exhibits

The exhibits listed in the Index to Exhibits, which appears on pages 55 through 59 are filed
as part of this annual report.

(c)

The financial statements of OAO LUKOIL, which appear below, are filed in accordance with Rule
3-09 of Regulation S-X.

We have audited the accompanying consolidated balance sheets of OAO LUKOIL and its subsidiaries as
of December 31, 2009 and 2008, and the related consolidated statements of income, stockholders
equity and comprehensive income, and cash flows for each of the years in the three-year period
ended December 31, 2009. These consolidated financial statements are the responsibility of the
management of OAO LUKOIL. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United
States of America. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit
includes consideration of internal control over financial reporting as a basis for designing audit
procedures that are appropriate in the circumstances, but not for the purpose of expressing an
opinion on the effectiveness of the companys internal control over financial reporting.
Accordingly, we express no such opinion. An audit also includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits provide a reasonable basis for
our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all
material respects, the financial position of OAO LUKOIL and its subsidiaries as of December 31,
2009 and 2008, and the results of their operations and their cash flows for each of the years in
the three-year period ended December 31, 2009, in conformity with accounting principles generally
accepted in the United States of America.

The primary activities of OAO LUKOIL (the Company) and its subsidiaries (together, the Group)
are oil exploration, production, refining, marketing and distribution. The Company is the ultimate
parent entity of this vertically integrated group of companies.

The Group was established in accordance with Presidential Decree 1403, issued on November 17, 1992.
Under this decree, on April 5, 1993, the Government of the Russian Federation transferred to the
Company 51% of the voting shares of fifteen enterprises. Under Government Resolution 861 issued on
September 1, 1995, a further nine enterprises were transferred to the Group during 1995. Since
1995, the Group has carried out a share exchange program to increase its shareholding in each of
the twenty-four founding subsidiaries to 100%.

From formation, the Group has expanded substantially through consolidation of its interests,
acquisition of new companies and establishment of new businesses.

Business
and economic environment

The Russian Federation has been experiencing political and economic change, that has affected and
will continue to affect the activities of enterprises operating in this environment. Consequently,
operations in the Russian Federation involve risks, which do not typically exist in other markets.
In addition, the recent contraction in the capital and credit markets has further increased the
level of economic uncertainty in the environment.

The accompanying financial statements reflect managements assessment of the impact of the business
environment in the countries in which the Group operates on the operations and the financial
position of the Group. The future business environments may differ from managements assessment.

Basis of preparation

These consolidated financial statements have been prepared by the Company in accordance with
accounting principles generally accepted in the United States of America (US GAAP).

Note 2. Summary of significant accounting policies

Principles of consolidation

These consolidated financial statements include the financial position and results of the Company,
controlled subsidiaries of which the Company directly or indirectly owns more than 50% of the
voting interest, unless minority stockholders have substantive participating rights, and variable
interest entities where the Group is determined to be the primary beneficiary. Other significant
investments in companies of which the Company directly or indirectly owns between 20% and 50% of
the voting interest and over which it exercises significant influence but not control, are
accounted for using the equity method of accounting. Investments in companies of which the Company
directly or indirectly owns more than 50% of the voting interest but where minority stockholders
have substantive participating rights are accounted for using the equity method of accounting.
Undivided interests in oil and gas joint ventures are accounted for using the proportionate
consolidation method. Investments in other companies are recorded at cost. Equity investments and
investments in other companies are included in Investments in the consolidated balance sheet.

The preparation of financial statements in conformity with US GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements, and the reported
amounts of revenues and expenses during the reporting period. Significant items subject to such
estimates and assumptions include the carrying value of oil and gas properties and other property,
plant and equipment, goodwill impairment assessment, asset retirement obligations, deferred income
taxes, valuation of financial instruments, and obligations related to employee benefits. Eventual
actual amounts could differ from those estimates.

Revenue

Revenues from the production and sale of crude oil and petroleum products are recognized when title
passes to customers at which point the risks and rewards of ownership are assumed by the customer
and the price is fixed or determinable. Revenues include excise on petroleum products sales and
duties on export sales of crude oil and petroleum products.

Revenues from non-cash sales are recognized at the fair market value of the crude oil and petroleum
products sold.

Foreign currency translation

The Company maintains its accounting records in Russian rubles. The Companys functional currency
is the US dollar and the Groups reporting currency is the US dollar.

For operations in the Russian Federation and for the majority of operations outside the Russian
Federation, the US dollar is the functional currency. Where the US dollar is the functional
currency, monetary assets and liabilities have been translated into US dollars at the rate
prevailing at each balance sheet date. Non-monetary assets and liabilities have been translated
into US dollars at historical rates. Revenues, expenses and cash flows have been translated into US
dollars at rates, which approximate actual rates at the date of the transaction. Translation
differences resulting from the use of these rates are included in the consolidated statement of
income.

For certain other operations outside the Russian Federation, where the US dollar is not the
functional currency and the economy is not hyperinflationary, assets and liabilities are translated
into US dollars at year-end exchange rates and revenues and expenses are translated at average
exchange rates for the year. Resulting translation adjustments are reflected as a separate
component of comprehensive income.

In all cases, foreign currency transaction gains and losses are included in the consolidated
statement of income.

As of December 31, 2009, 2008 and 2007, exchange rates of 30.24, 29.38 and 24.55 Russian rubles to
the US dollar, respectively, have been used for translation purposes.

The Russian ruble and other currencies of republics of the former Soviet Union are not readily
convertible outside of their countries. Accordingly, the translation of amounts recorded in these
currencies into US dollars should not be construed as a representation that such currency amounts
have been, could be or will in the future be converted into US dollars at the exchange rate shown
or at any other exchange rate.

Cash and cash equivalents

Cash and cash equivalents include all highly liquid investments with an original maturity of three
months or less.

Cash funds for which restrictions on immediate use exist are accounted for within other non-current
assets.

Accounts and notes receivable

Accounts and notes receivable are recorded at their transaction amounts less provisions for
doubtful debts. Provisions for doubtful debts are recorded to the extent that there is a likelihood
that any of the amounts due will not be collected. Non-current receivables are discounted to the
present value of expected cash flows in future periods using the original discount rate.

Inventories

Starting from January 1, 2009, the Group elected to change the inventory accounting method for
finished goods and purchased products from the weighted average to the FIFO cost method. Management
believes the FIFO cost method for these inventory categories is preferable because it reflects the
results of the most recent business activity and allows a more rapid reflection of results of
operations, and represents a better matching of cost of sales with related sales. The Group
determined that it is impracticable to calculate the cumulative effect of applying this change
retrospectively because of the lack of information available.

The cost of all other inventory categories is determined using an average cost method.

Investments

Debt and equity securities are classified into one of three categories: trading,
available-for-sale, or held-to-maturity.

Trading securities are bought and held principally for the purpose of selling in the near term.
Held-to-maturity securities are those securities in which a Group company has the ability and
intent to hold until maturity. All securities not included in trading or held-to-maturity are
classified as available-for-sale.

Trading and available-for-sale securities are recorded at fair value. Held-to-maturity securities
are recorded at cost, adjusted for the amortization or accretion of premiums or discounts.
Unrealized holding gains and losses on trading securities are included in the consolidated
statement of income. Unrealized holding gains and losses, net of the related tax effect, on
available-for-sale securities are reported as a separate component of comprehensive income until
realized. Realized gains and losses from the sale of available-for-sale securities are determined
on a specific identification basis. Dividends and interest income are recognized in the
consolidated statement of income when earned.

A permanent decline in the market value of any available-for-sale or held-to-maturity security
below cost is accounted for as a reduction in the carrying amount to fair value. The impairment is
charged to the consolidated statement of income and a new cost base for the security is
established. Premiums and discounts are amortized or accreted over the life of the related
held-to-maturity or available-for-sale security as an adjustment to yield using the effective
interest rate method and such amortization and accretion is recorded in the consolidated statement
of income.

Property, plant and equipment

Oil and gas properties are accounted for using the successful efforts method of accounting whereby
property acquisitions, successful exploratory wells, all development costs, and support equipment
and facilities are capitalized. Unsuccessful exploratory wells are expensed when a well is
determined to be non-productive. Other exploratory expenditures, including geological and
geophysical costs are expensed as incurred.

The Group continues to capitalize costs of exploratory wells and exploratory-type stratigraphic
wells for more than one year after the completion of drilling if the well has found a sufficient
quantity of reserves to justify its completion as a producing well and the company is making
sufficient progress assessing the reserves and the economic and operating viability of the project.
If these conditions are not met or if information that raises substantial doubt about the economic
or operational viability of the project is obtained, the well would be assumed impaired, and its
costs, net of any salvage value, would be charged to expense.

Depreciation, depletion and amortization of capitalized costs of oil and gas properties is
calculated using the unit-of-production method based upon proved reserves for the cost of property
acquisitions and proved developed reserves for exploration and development costs.

Production and related overhead costs are expensed as incurred.

Depreciation of assets not directly associated with oil production is calculated on a straight-line
basis over the economic lives of such assets, estimated to be in the following ranges:

Buildings and constructions

5  40 Years

Machinery and equipment

5  20 Years

In addition to production assets, certain Group companies also maintain and construct social assets
for the use of local communities. Such assets are capitalized only to the extent that they are
expected to result in future economic benefits to the Group. If capitalized, they are depreciated
over their estimated economic lives.

Significant unproved properties are assessed for impairment individually on a regular basis and any
estimated impairment is charged to expense.

Asset retirement obligations

The Group records the fair value of liabilities related to its legal obligations to abandon,
dismantle or otherwise retire tangible long-lived assets in the period in which the liability is
incurred. A corresponding increase in the carrying amount of the related long-lived asset is also
recorded. Subsequently, the liability is accreted for the passage of time and the related asset is
depreciated using the unit-of-production method.

Goodwill and other intangible assets

Goodwill represents the excess of the cost of an acquired entity over the net of the amounts
assigned to assets acquired and liabilities assumed. It is assigned to reporting units as of the
acquisition date. Goodwill is not amortized, but is tested for impairment at least on an annual
basis and between annual tests if an event occurs or circumstances change that would more likely
than not reduce the fair value of a reporting unit below its carrying amount. The impairment test
requires estimating the fair value of a reporting unit and comparing it with its carrying amount,
including goodwill assigned to the reporting unit. If the estimated fair value of the reporting
unit is less than its net carrying amount, including goodwill, then the goodwill is written down to
its implied fair value.

Intangible assets with indefinite useful lives are tested for impairment at least annually.
Intangible assets that have limited useful lives are amortized on a straight-line basis over the
shorter of their useful or legal lives.

Long-lived assets, such as oil and gas properties (other than unproved properties), other property,
plant, and equipment, and purchased intangibles subject to amortization, are assessed for
impairment whenever events or changes in circumstances indicate that the carrying amount of an
asset group may not be recoverable. Recoverability of assets to be held and used is measured by a
comparison of the carrying amount of an asset group to the estimated undiscounted future cash flows
expected to be generated by that group. If the carrying amount of an asset group exceeds its
estimated undiscounted future cash flows, an impairment charge is recognized by writing down the
carrying amount to the estimated fair value of the asset group, generally determined as discounted
future net cash flows. Assets to be disposed of are separately presented in the balance sheet and
reported at the lower of the carrying amount or fair value less costs to sell, and are no longer
depreciated. The assets and liabilities of a disposed group classified as held for sale are
presented separately in the appropriate asset and liability sections of the balance sheet.

Income taxes

Deferred income tax assets and liabilities are recognized in respect of future tax consequences
attributable to temporary differences between the carrying amounts of existing assets and
liabilities for the purposes of the consolidated financial statements and their respective tax
bases and in respect of operating loss and tax credit carryforwards. Deferred income tax assets and
liabilities are measured using enacted tax rates expected to apply to taxable income in the years
in which those temporary differences are expected to reverse and the assets be recovered and
liabilities settled. The effect on deferred income tax assets and liabilities of a change in tax
rates is recognized in the consolidated statement of income in the reporting period which includes
the enactment date.

The ultimate realization of deferred income tax assets is dependent upon the generation of future
taxable income in the reporting periods in which the originating expenditure becomes deductible. In
assessing the realizability of deferred income tax assets, management considers whether it is more
likely than not that the deferred income tax assets will be realized. In making this assessment,
management considers the scheduled reversal of deferred income tax liabilities, projected future
taxable income, and tax planning strategies.

An income tax position is recognized only if the uncertain position is more likely than not of
being sustained upon examination, based on its technical merits. A recognized income tax position
is measured at the largest amount that is greater than 50% likely of being realized. Changes in
recognition or measurement are reflected in the period in which the change in judgment occurs. The
Company records interest and penalties relating to income tax in income tax expense in the
consolidated statements of income.

Interest-bearing borrowings

Interest-bearing borrowings are initially recorded at the value of net proceeds received. Any
difference between the net proceeds and the redemption value is amortized at a constant rate over
the term of the borrowing. Amortization is included in the consolidated statement of income each
year and the carrying amounts are adjusted as amortization accumulates.

If borrowings are repurchased or settled before maturity, any difference between the amount paid
and the carrying amount is recognized in the consolidated statement of income in the period in
which the repurchase or settlement occurs.

The expected costs in respect of pension obligations of Group companies are determined by an
independent actuary. Obligations in respect of each employee are accrued over the reporting periods
during which the employee renders service in the Group.

The Group recognizes the funded status of postretirement defined benefit plan in the balance sheet
with corresponding adjustments to accumulated other comprehensive income. The adjustment to
accumulated other comprehensive income represents the net unrecognized actuarial gains and
unrecognized prior service costs. These amounts are subsequently recognized as net periodic
benefit cost. Further, actuarial gains and losses that arise in subsequent periods and are not
recognized as net periodic benefit cost in the same periods are recognized as a component of other
comprehensive income. These amounts are subsequently recognized as a component of net periodic
benefit cost on the same basis as the amounts recognized in accumulated other comprehensive
income.

Treasury stock

Purchases by Group companies of the Companys outstanding stock are recorded at cost and classified
as treasury stock within Stockholders equity. Shares shown as Authorized and Issued include
treasury stock. Shares shown as Outstanding do not include treasury stock.

Earnings per share

Basic earnings per share is computed by dividing net income available to common stockholders of the
Company by the weighted-average number of shares of common stock outstanding during the reporting
period. A calculation is carried out to establish if there is potential dilution in earnings per
share if convertible securities were to be converted into shares of common stock or contracts to
issue shares of common stock were to be exercised. If there is such dilution, diluted earnings per
share is presented.

Contingencies

Certain conditions may exist as of the balance sheet date, which may result in losses to the Group
but the impact of which will only be resolved when one or more future events occur or fail to
occur.

If a Group companys assessment of a contingency indicates that it is probable that a material loss
has been incurred and the amount of the liability can be estimated, then the estimated liability is
accrued and charged to the consolidated statement of income. If the assessment indicates that a
potentially material loss is not probable, but is reasonably possible, or is probable, but cannot
be estimated, then the nature of the contingent liability, together with an estimate of the range
of possible loss, is disclosed in the notes to the consolidated financial statements. Loss
contingencies considered remote or related to unasserted claims are generally not disclosed unless
they involve guarantees, in which case the nature of the guarantee is disclosed.

Environmental expenditures

Estimated losses from environmental remediation obligations are generally recognized no later than
completion of remedial feasibility studies. Group companies accrue for losses associated with
environmental remediation obligations when such losses are probable and reasonably estimable. Such
accruals are adjusted as further information becomes available or circumstances change. Costs of
expected future expenditures for environmental remediation obligations are not discounted to their
present value.

The Groups derivative activity is limited to certain petroleum products marketing and trading
outside of its physical crude oil and petroleum products businesses and hedging of commodity price
risks. Currently this activity involves the use of futures and swaps contracts together with
purchase and sale contracts that qualify as derivative instruments. The Group accounts for these
activities under the mark-to-market methodology in which the derivatives are revalued each
accounting period. Resulting realized and unrealized gains or losses are presented in the
consolidated statement of income on a net basis. Unrealized gains and losses are carried as assets
or liabilities on the consolidated balance sheet.

Share-based payments

The Group accounts for liability classified share-based payment awards to employees at fair value
on the date of grant and as of each reporting date. Expenses are recognized over the vesting
period. Equity classified share-based payment awards to employees are valued at fair value on the
date of grant and expensed over the vesting period.

Comparative amounts

Certain prior period amounts have been reclassified to conform with the current periods
presentation.

Recent accounting
pronouncements

In February 2010, the FASB issued Accounting Standards Update (ASU) No. 2010-09, Subsequent
events which amends Accounting Standards Codification (ASC) No. 855 (former SFAS No. 165,
Subsequent events), issued in May 2009. The Group adopted ASC No. 855 starting from the second
quarter of 2009. These standards address accounting and disclosure requirements related to
subsequent events and require management of an entity which is an SEC filer or is a conduit bond
obligator for conduit securities that are traded in a public market to evaluate subsequent event
through the date that the financial statements are issued. Entities that do not meet these criteria
should evaluate subsequent events through the date the financial statements are available to be
issued and are required to disclose the date through which subsequent events have been evaluated.
The Group determined that it should evaluate subsequent events through the date the financial
statements are available to be issued and applied the requirements of ASU No. 2010-09 starting from
the financial statements for 2009.

In January 2010, the FASB issued ASU No. 2010-01, Accounting for Distributions to Shareholders
with Components of Stock and Cash which addresses how an entity should account for the stock
portion of a dividend in certain arrangements when a shareholder makes an election to receive cash
or stock, subject to limitations on the amount of the dividend to be issued in cash. The stock
portion of the dividend should be accounted for as a stock issuance upon distribution, resulting in
basic earnings per share being adjusted prospectively. Prior to distribution, the entitys
obligation to issue shares would be reflected in diluted earnings-per-share based on the guidance
in ASC No. 260, which addresses contracts that may be settled in shares. This ASU is effective for
interim and annual periods ending after December 15, 2009. The Group adopted ASU No. 2010-01 for
the 2009 annual financial statements. This adoption did not have a material impact on the Groups
results of operations, financial position or cash flows.

In January 2010, the FASB issued ASU No. 2010-02, Accounting and Reporting for Decreases in
Ownership of a Subsidiary  A Scope Clarification to clarify the scope of ASC Subtopic No. 810-10,
Consolidation  Overall. This ASU specifies that the guidance in ASC Subtopic No. 810-10 on
accounting for decreases in ownership of a subsidiary applies to: (1) a subsidiary or group of
assets that constitutes a business or nonprofit activity; (2) a subsidiary that is a business or a
nonprofit activity that is transferred to an equity method investee or a joint venture; and (3) an
exchange of a group of assets that constitute a business or nonprofit activity for a noncontrolling
interest in an entity. If a companys ownership interest in a subsidiary that is not a business or
nonprofit activity decreases, then other accounting guidance generally would be applied based on
the nature of the transaction. The new pronouncement also clarifies that the recent guidance on
accounting for decreases in ownership of a subsidiary does not apply if the transaction is a sale
of in-substance real estate or a conveyance of oil and gas properties. This ASU is effective for
interim and annual periods ending after December 15, 2009 and the guidance should be applied on a
retrospective basis to the first period in which the company adopted ASC No. 810. The Group adopted
ASU No. 2010-02 for the 2009 annual financial statements. This adoption did not have a material
impact on the Groups results of operations, financial position or cash flows.

In January 2010, the FASB issued ASU No. 2010-03, Extractive activities  Oil and Gas (Topic 932):
Oil and Gas Reserve Estimation and Disclosures. The main provisions of ASU No. 2010-03 are the
following: (1) expanding the definition of oil- and gas-producing activities to include the
extraction of saleable hydrocarbons, in solid, liquid, or gaseous state, from oil sands, shale,
coalbeds, or other nonrenewable resources that are intended to be upgraded into synthetic oil or
gas, and activities undertaken with a view to such extraction; (2) entities should use
first-day-of-the-month price during the 12-month period (the 12-months average price) in
calculating proved oil and gas reserves and estimating related standardized measure of discounted
net cash flows; (3) requiring entities to disclose separately information about reserves quantities
and financial statement amounts for geographic areas that represent 15 percent or more of proved
reserves; (4) separate disclosure for consolidated entities and equity method investments. ASU No.
2010-03 is effective for annual reporting periods ending on or after December 31, 2009. The Group
adopted ASU No. 2010-03 for the 2009 annual financial statements. This adoption did not have a
material impact on the Groups reported reserves evaluation, results of operations, financial
position or cash flows.

In June 2009, the FASB issued amendments to ASC No. 810 (former FASB Interpretation No. 46(R),
Consolidation of Variable Interest Entities) to address the effects of the elimination of the
qualifying special purpose entity concept. More specifically, it requires a qualitative rather than
a quantitative approach to determine the primary beneficiary of a variable interest entity, it
amends certain guidance pertaining to the determination of the primary beneficiary when related
parties are involved, and it amends certain guidance for determining whether an entity is a
variable interest entity. Additionally, these amendments require continuous assessment of whether
an enterprise is the primary beneficiary of a variable interest entity. Amendments are effective on
January 1, 2010, and the Group does not expect any material impact on its results of operations,
financial position or cash flows upon adoption.

In June 2009, the FASB issued ASC No. 105 (former SFAS No. 168, The FASB Accounting Standards
Codification and the Hierarchy of Generally Accepted Accounting Principles). The FASB Accounting
Standards Codification (Codification) is the exclusive authoritative reference for US GAAP
recognized by the FASB and applied by nongovernmental entities, except for SEC rules and
interpretive releases, which are also authoritative US GAAP for SEC registrants. The change
established by ASC No. 105 divides nongovernmental US GAAP into authoritative Codification and
guidance that is not authoritative. The contents of the Codification carry the same level of
authority, eliminating the four-level US GAAP hierarchy previously set forth in SFAS No. 162. The
Codification supersedes all non-SEC accounting and reporting standards. All other
non-grandfathered, non-SEC accounting literature not included in the Codification became
nonauthoritative. This Statement is effective for financial statements issued for interim and
annual periods ending after September 15, 2009. The Group adopted ASC No. 105 starting from the
third quarter of 2009. This adoption did not have any impact on the Groups results of operations,
financial position or cash flows.

In December 2008, the FASB amended ASC Nos. 310, 320, 323, 405, 460, 470, 712, 715, 810, 815, 860,
954 and 958 (former FSP FAS 140-4 and FIN 46(R)-8, Disclosures about Transfers of Financial Assets
and Interest in Variable Interest Entities). It requires additional disclosures about transfers of
financial assets and requires public entities, including sponsors that have a variable interest in
a variable interest entity, to provide additional disclosures about their involvement with variable
interest entities. The Group adopted new provisions starting from the fourth quarter of 2008. This
adoption did not have a material impact on the Groups results of operations, financial position or
cash flows.

In March 2008, the FASB issued ASC No. 815 (former SFAS No. 161, Disclosures about Derivative
Instruments and Hedging Activities). This ASC improves financial reporting about derivative
instruments and hedging activities by enhanced disclosures of their effects on an entitys
financial position, financial performance and cash flows. The Group adopted the provisions of ASC
No. 815 starting from the first quarter of 2009. This adoption did not have any impact on the
Groups results of operations, financial position or cash flows.

In December 2007, the FASB issued ASC No. 805 (former SFAS No. 141 (Revised), Business
combinations). This ASC applies to all transactions in which an entity obtains control of one or
more businesses. In April 2009, this ASC was amended and requires an entity to recognize the total
fair value of assets acquired and liabilities assumed in a business combination; to recognize and
measure the goodwill acquired in the business combination or gain from a bargain purchase and
modifies the disclosure requirements. The Group adopted the provisions of ASC No. 805 for business
combinations for which the acquisition date is after December 31, 2008. This adoption did not have
any impact on the Groups results of operations, financial position or cash flows.

In December 2007, the FASB issued ASC No. 810 (former SFAS No. 160, Noncontrolling Interests in
Consolidated Financial Statements  an amendment of ARB No. 51). This ASC applies to all entities
that prepare consolidated financial statements (except not-for-profit organizations) and affects
those which have an outstanding noncontrolling interest (or minority interest) in their
subsidiaries or which have to deconsolidate a subsidiary. This ASC changes the classification of a
non-controlling interest; establishing a single method of accounting for changes in the parent
companys ownership interest that does not result in deconsolidation and requires a parent company
to recognize a gain or loss when a subsidiary is deconsolidated. The Group prospectively adopted
the provisions of ASC No. 810 in the first quarter of 2009, except for the presentation and
disclosure requirements which were applied retrospectively. This adoption did not have any impact
on the Groups results of operations, financial position or cash flows.

In February 2007, the FASB issued ASC Nos. 470, 825 and 954 (former SFAS No. 159, The Fair Value
Option for Financial Assets and Financial Liabilities). These ASC expands the possibility of using
fair value measurements and permits enterprises to choose to measure certain financial assets and
financial liabilities at fair value. Enterprises shall report unrealized gains and losses on items
for which the fair value option has been elected in earnings in each subsequent period. The Group
adopted the provisions of ASC Nos. 470, 825 and 954 in the first quarter of 2008 and elected not to
use the fair value option for its financial assets and financial liabilities not already carried at
fair value in accordance with other standards. This adoption did not have any impact on the Groups
results of operations, financial position or cash flows.

In September 2006, the FASB issued ASC No. 820 (former SFAS No. 157, Fair Value Measurements),
which establishes a single authoritative definition of fair value, sets out a framework for
measuring fair value and requires additional disclosures about fair value measurements. Effective
January 1, 2009, the Group fully adopted ASC No. 820. Because there usually is a lack of quoted
market prices for long-lived assets, the Group determines fair value using the present value of
estimated future net cash flows from using these assets or by using historical data of market
transactions with similar assets where possible. Fair value used in the initial recognition of
asset retirement obligations is determined using the present value of expected future dismantlement
costs, which are estimated based on the costs for dismantlement services for similar assets
providing by third parties. This adoption did not have a material impact on the Groups results of
operations, financial position or cash flows.

The summarized financial information below is in respect of equity method affiliates and corporate
joint ventures. The companies are primarily engaged in crude oil exploration, production, marketing
and distribution operations in the Russian Federation, crude oil production and marketing in
Kazakhstan, and refining operations in Europe.

Year ended

Year ended

Year ended

December 31, 2009

December 31, 2008

December 31, 2007

Groups

Groups

Groups

Total

share

Total

share

Total

share

Revenues

5,139

2,275

4,590

2,144

2,930

1,382

Income before income taxes

1,305

478

1,602

807

1,398

650

Less income taxes

(407

)

(127

)

(869

)

(432

)

(605

)

(303

)

Net income

898

351

733

375

793

347

As of December 31, 2009

As of December 31, 2008

Groups

Groups

Total

Share

Total

share

Current assets

6,796

1,524

2,023

982

Property, plant and equipment

18,877

5,284

5,872

2,841

Other non-current assets

607

240

544

269

Total assets

26,280

7,048

8,439

4,092

Short-term debt

442

274

158

47

Other current liabilities

3,982

817

1,188

557

Long-term debt

7,769

732

890

392

Other non-current liabilities

1,633

471

220

108

Net assets

12,454

4,754

5,983

2,988

In December 2009, the Group acquired the remaining a 46.0% interest in its equity affiliate
LUKARCO B.V. for $1.6 billion, thereby increasing the ownership stake to 100%. LUKARCO B.V. is a
holding company, which owns a 5% share in Tengizchevroil, a joint venture which develops the Tengiz
and Korolevskoe fields in Kazakhstan, and a 12.5% share in the Caspian Pipeline Consortium (CPC),
which carries Kazakhstani and Russian oil to Novorossiysk marine terminal. Therefore the Group
increased the ownership in Tengizchevroil from 2.7% to 5% and the ownership in CPC from 6.75% to
12.5%. The first installment in the amount of $300 million was paid in December 2009; the remaining
amount should be paid no later than two years after the acquisition. The Group is using the equity
method of accounting for investments in Tengizchevroil and CPC.

In June 2009, a Group company entered into an agreement with Total to acquire a 45% interest in the
TRN refinery in the Netherlands. The transaction was finalized in September 2009 in the amount of
approximately $700 million. The Group supplies crude oil and market refined products in line with
its equity stake in the refinery. The refinery has the flexibility to process Urals blend crude oil
as well as significant volumes of straight-run fuel oil and vacuum gasoil, which will allow the
Group to integrate the plant into its crude oil supply and refined products marketing operations.
This plant with a Nelson complexity index of 9.8 has an annual topping capacity of 7.9 million
tonnes and an annual capacity of a hydro-cracking unit of approximately 3.4 million tonnes. This
acquisition was made in accordance with the Groups plans to develop its refining capacity in
Europe.

In June 2008, a Group company signed an agreement with ERG S.p.A. to establish a joint venture to
operate the ISAB refinery complex in Priolo, Italy. In December 2008, the Group completed the
acquisition of a 49% stake in the joint venture for 1.45 billion (approximately $1.83 billion) and
paid 600 million (approximately $762 million) as a first installment. The remaining amount was
paid in February 2009. The seller has a put option, the effect of which would be to increase the
Groups stake in the company operating the ISAB refinery complex up to 100%. As of December 31,
2009, the fair value of this option for the Group is zero. The agreement states that each partner
is responsible for procuring crude oil and marketing refined products in line with its equity stake
in the joint venture. The ISAB refinery complex has the flexibility to process Urals blend crude
oil, and the Group integrated its share of the ISAB refinery complex capacity into its crude oil
supply and refined products marketing operations. The ISAB refinery complex includes three jetties
and storage tanks totaling 3,700 thousand cubic meters and has an annual refining capacity of 16
million tonnes.

In December 2009, the Company performed a regular annual impairment test of its exploration
and production assets. The test was based on geological models and development programs, which are
revised on a regular basis. As a result of the test, the Company recognized an impairment loss of
$238 million for certain properties in the Timan-Pechora and Central European regions of Russia.
The fair value of these assets was determined using the present value of the expected cash flows.
The Group also recognized an impairment loss of $63 million related to the project in Iran due to
incapability of undertaking further works because of the threat of economic sanctions of the US
Government.

In June 2008, the Company performed an impairment test of certain exploration and production assets
located in oil fields in the Timan-Pechora region of Russia, due to a revision of geological
models. The revision resulted in a reduction of planned development activities on these oil fields.
The fair value of these assets was determined using the present value of the expected cash flows.
As a result, the Company recognized an impairment loss of $156 million. In December 2008, the Group
recognized an impairment loss of $58 million relating to retail petrol stations in the USA.

As of December 31, 2009 and 2008, the asset retirement obligations amounted to $1,199 million and
$728 million, respectively, of which $10 million was included in Other current liabilities in the
consolidated balance sheets as of each balance sheet date. During 2009 and 2008, asset retirement
obligations changed as follows:

The carrying value of goodwill and other intangible assets as of December 31, 2009 and 2008 was as
follows:

As of December

As of December

31, 2009

31, 2008

Amortized intangible assets

Software

419

500

Licenses and other assets

465

335

Goodwill

769

324

Total goodwill and other intangible assets

1,653

1,159

All goodwill amounts relate to the refining, marketing and distribution segment.

In the fourth quarter of 2009, the Group recognized goodwill related to acquisitions of a 100%
interest in the Akpet group, 100% interests in OOO Smolenskneftesnab, OOO IRT Investment, OOO PM
Invest and OOO Retaier House and 100% interests in ZAO Association Grand and OOO Mega Oil M in the
amount of $114 million, $165 million and $196 million, respectively (refer to Note 16. Business
combinations).

In December 2008, the Group recognized an impairment loss of $100 million relating to goodwill on
the acquisition of Beopetrol due to the change in the economic environment. Beopetrol is a
marketing and distribution company operating a chain of retail petrol stations in Serbia. The fair
value of Beopetrol was determined using the present value of the expected cash flows.

Short-term borrowings from third parties are unsecured and include amounts repayable in US
dollars of $282 million and $1,529 million, amounts repayable in Euro of $76 million and $676
million and amounts repayable in Russian rubles of $18 million and $70 million as of December 31,
2009 and 2008, respectively. The weighted-average interest rate on short-term borrowings from third
parties was 2.02% and 5.15% per annum as of December 31, 2009 and 2008, respectively.

Russian ruble bonds

In June 2009, the Company issued 15 million short-term stock exchange bonds with a face value of
1,000 Russian rubles each. Bonds were placed at the face value with a maturity of 364 days. The
coupon yield is 13.5% per annum and is paid at the maturity date.

Note 11. Long-term debt

As of December

As of December

31, 2009

31, 2008

Long-term loans and borrowings from third
parties (including loans from banks in the
amount of $3,967 million and $3,333 million as of
December 31, 2009 and 2008, respectively)

4,043

3,384

Long-term loans and borrowings from related parties

1,939

2,165

6.375% US dollar bonds, maturing 2014

895



6.356% US dollar bonds, maturing 2017

500

500

7.250% US dollar bonds, maturing 2019

595



6.656% US dollar bonds, maturing 2022

500

500

7.25% Russian ruble bonds, maturing 2009



204

7.10% Russian ruble bonds, maturing 2011

265

272

8.00% Russian ruble bonds, maturing 2012



8

13.35% Russian ruble bonds, maturing 2012

827



9.20% Russian ruble bonds, maturing 2012

331



7.40% Russian ruble bonds, maturing 2013

198

204

Capital lease obligations

215

271

Total long-term debt

10,308

7,508

Current portion of long-term debt

(1,043

)

(931

)

Total non-current portion of long-term debt

9,265

6,577

Long-term loans and borrowings

Long-term loans and borrowings from third parties include amounts repayable in US dollars of $3,493
million and $2,844 million, amounts repayable in Euro of $487 million and $375 million and amounts
repayable in Russian rubles of $42 million and $112 million as of December 31, 2009 and 2008,
respectively. This debt has maturity dates from 2010 through 2021. The weighted-average interest
rate on long-term loans and borrowings from third parties was 2.77% and 4.09% per annum as of
December 31, 2009 and 2008, respectively. A number of long-term loan agreements contain certain
financial covenants due levels of which are being met by the Group. Approximately 15% of total
long-term debt is secured by export sales and property, plant and equipment.

The Company has a secured loan agreement with Deutche Bank AG with an outstanding amount of $1,200
million as of December 31, 2009, maturing up to 2012. Borrowings under this agreement bear interest
at three month LIBOR plus 4.0% per annum.

A Group company has an unsecured syndicated loan agreement with an outstanding amount of $860
million as of December 31, 2009, with maturity dates up to 2013. The loan was arranged by ABN AMRO
Bank, Banco Bilbao Vizcaya Argentaria, BNP Paribas, The Bank of Tokyo-Mitsubishi UFJ, ING Bank,
Mizuho Corporate Bank and WestLB. Borrowings under this agreement bear interest from three month
LIBOR plus 0.85% to three month LIBOR plus 0.95% per annum.

Two Group companies have unsecured loan agreements with an outstanding amount of $424 million as of
December 31, 2009, maturing up to 2011. The loans were arranged by ABN AMRO Bank, The Bank of
Tokyo-Mitsubishi UFJ, Barclays Capital, BNP Paribas, Citibank, Dresdner Kleinwort, ING Bank and
WestLB. Borrowings under these agreements bear interest at three month LIBOR plus 3.25% per annum.

The Company has an unsecured syndicated loan agreement with the European Bank for Reconstruction
and Development with an outstanding amount of $258 million as of December 31, 2009, maturing up to
2017. Borrowings under this agreement bear interest from six month LIBOR plus 0.45% to six month
LIBOR plus 0.65% per annum.

A Group company has a secured loan agreement, arranged by Credit Suisse, supported by an Overseas
Private Investment Corporation guarantee, with an outstanding amount of $175 million as of December
31, 2009. Borrowings under this agreement bear interest at six month LIBOR plus 4.8% per annum and
have maturity dates up to 2015.

A Group company has an unsecured loan agreement with Citibank with an outstanding amount of $129
million as of December 31, 2009, maturing up to 2019. Borrowings under this agreement bear interest
at euribor plus 0.125% per annum.

The Company has an unsecured syndicated loan agreement, arranged by ABN AMRO Bank and CALYON with
an outstanding amount of $125 million as of December 31, 2009, maturing up to 2012. Borrowings
under this agreement bear interest at three month LIBOR plus 0.40% per annum.

A Group company has an unsecured loan agreement with BNP Paribas with an outstanding amount of $119
million as of December 31, 2009, maturing up to 2018. Borrowings under this agreement bear interest
at six month euribor plus 0.15% per annum.

A Group company has an unsecured loan agreement with Citibank with an outstanding amount of $100
million as of December 31, 2009, maturing in 2011. Borrowings under this agreement bear interest at
one month LIBOR plus 0.90% per annum.

As of December 31, 2009, the Group has a number of other loan agreements with fixed rates with a
number of banks and other organizations totaling $239 million, maturing from 2010 to 2021. The
weighted average interest rate under these loans was 4.12% per annum.

As of December 31, 2009, the Group has a number of other floating rate loan agreements with a
number of banks and other organizations totaling $414 million, maturing from 2010 to 2017. The
weighted average interest rate under these loans was 2.16% per annum.

A Group company has a number of loan agreements nominated in Russian rubles with ConocoPhillips,
the Groups related party, with an outstanding amount of $1,939 million as of December 31, 2009.
This amount includes $1,660 million loaned by ConocoPhillips to a joint venture OOO
Narianmarneftegaz (NMNG) (refer to Note 17. Consolidation of Variable Interest Entity).
Borrowings under these agreements bear interest at fixed rates ranging from 6.8% to 8.2% per annum
and have maturity dates up to 2038. These agreements are a part of the Companys broad-based
strategic alliance with ConocoPhillips and this financing is used to develop oil production and the
distribution infrastructure in the Timan-Pechora region of the Russian Federation.

US dollar bonds

In November 2009, a Group company issued two tranches of non-convertible bonds totaling $1.5
billion. The first tranche totaling $900 million with a coupon yield of 6.375% per annum was placed
with a maturity of 5 years at a price of 99.474% of the bonds face value. The resulting yield to
maturity for the first tranche is 6.500%. The second tranche totaling $600 million with a coupon
yield of 7.250% per annum was placed with a maturity of 10 years at a price of 99.127% of the
bonds face value. The resulting yield to maturity for the second tranche is 7.375%. These tranches
have a half year coupon period.

In June 2007, a Group company issued non-convertible bonds totaling $1 billion. $500 million were
placed with a maturity of 10 years and a coupon yield of 6.356% per annum. Another $500 million
were placed with a maturity of 15 years and a coupon yield of 6.656% per annum. All bonds were
placed at the face value and have a half year coupon period.

Russian ruble bonds

In December 2009, the Company issued 10 million stock exchange bonds with a face value of 1,000
Russian rubles each. Bonds were placed at the face value with a maturity of 1,092 days. The bonds
have a 182 days coupon period and bear interest at 9.20% per annum.

In August 2009, the Company issued 25 million stock exchange bonds with a face value of 1,000
Russian rubles each. Bonds were placed at the face value with a maturity of 1,092 days. The bonds
have a 182 days coupon period and bear interest at 13.35% per annum.

In January 2007, OAO UGK TGK-8 (TGK-8), a subsidiary acquired in 2008 (refer to Note 16. Business
combinations) issued 3.5 million non-convertible bonds with a face value of 1,000 Russian rubles
each. These bonds were placed at the face value with a maturity of 5 years, with a coupon yield of
8.0% per annum and a half year coupon period. By the end of May 2009, TGK-8 redeemed all issued
bonds in accordance with the conditions of the bond issue.

In December 2006, the Company issued 14 million non-convertible bonds with a face value of 1,000
Russian rubles each. Eight million bonds were placed with a maturity of 5 years and a coupon yield
of 7.10% per annum and six million bonds were placed with a maturity of 7 years and a coupon yield
of 7.40% per annum. All bonds were placed at the face value and have a half year coupon period.

In November 2004, the Company issued 6 million non-convertible bonds with a face value of 1,000
Russian rubles each, maturing on November 23, 2009. The bonds had a half year coupon period and
beard interest at 7.25% per annum. In November 2009, the Company redeemed all issued bonds in
accordance with the conditions of the bond issue.

Maturities of long-term debt

Annual maturities of total long-term debt during the next five years, including the portion
classified as current, are $1,043 million in 2010, $1,890 million in 2011, $2,105 million in 2012,
$524 million in 2013, $1,094 million in 2014 and $3,652 million thereafter.

The Group is taxable in a number of jurisdictions within and outside of the Russian Federation and,
as a result, is subject to a variety of taxes as established under the statutory provisions of each
jurisdiction.

The total cost of taxation to the Group is reported in the consolidated statement of income as
Total income tax expense for income taxes, as Excise and export tariffs for excise taxes,
export tariffs and petroleum products sales taxes and as Taxes other than income taxes for other
types of taxation. In each category taxation is made up of taxes levied at various rates in
different jurisdictions.

Until January 1, 2009, operations in the Russian Federation were subject to a Federal income tax
rate of 6.5% and a regional income tax rate that varied from 13.5% to 17.5% at the discretion of
the individual regional administration. Starting on January 1, 2009, the Federal income tax rate is
2.0% and regional income tax rate varies from 13.5% to 18.0%. The Groups foreign operations are
subject to taxes at the tax rates applicable to the jurisdictions in which they operate.

As of January 1, 2009 and 2008, and during 2009, 2008 and 2007, the Group did not have any
unrecognized tax benefits and thus, no interest and penalties related to unrecognized tax benefits
were accrued. The Groups policy is to record interest and penalties related to unrecognized tax
benefits as components of income tax expense. In addition, the Group does not expect that the
amount of unrecognized tax benefits will change significantly within the next 12 months.

The Company and its Russian subsidiaries file standalone income tax returns in Russia. With a few
exceptions, income tax returns in Russia are open to examination by the Russian tax authorities for
the tax years beginning in 2007.

There are not currently, and have not been during the three years ended December 31, 2009, any
provisions in the taxation legislation of the Russian Federation to permit the Group to reduce
taxable profits in a Group company by offsetting tax losses in another Group company against such
profits. Tax losses of a Group company in the Russian Federation may, however, be used fully or
partially to offset taxable profits in the same company in any of the ten years following the year
of loss.

The following table is a reconciliation of the amount of income tax expense that would result from
applying the Russian combined statutory income tax rate to income before income taxes to total
income taxes:

Year ended

Year ended

Year ended

December 31, 2009

December 31, 2008

December 31, 2007

Income before income taxes

9,063

12,694

13,015

Notional income tax at Russian statutory rate

1,813

3,047

3,123

Increase (reduction) in income tax due to:

Non-deductible items, net

252

792

372

Foreign rate differences

68

159

84

Effect of enacted tax rate changes



(299

)



Domestic regional rate differences

(251

)

(261

)

(237

)

Change in valuation allowance

112

29

107

Total income tax expense

1,994

3,467

3,449

Taxes other than income taxes were:

Year ended

Year ended

Year ended

December 31, 2009

December 31, 2008

December 31, 2007

Mineral extraction tax

5,452

12,267

8,482

Social taxes and contributions

399

512

442

Property tax

470

405

313

Other taxes and contributions

153

280

130

Taxes other than income taxes

6,474

13,464

9,367

Deferred income taxes are included in the consolidated balance sheets as follows:

As of December

As of December

31,2009

31,2008

Other current assets

66

92

Deferred income tax assets  non-current

549

521

Other current liabilities

(50

)

(49

)

Deferred income tax liabilities  non-current

(2,080

)

(2,116

)

Net deferred income tax liability

(1,515

)

(1,552

)

The following tables set out the tax effects of each type of temporary differences which give
rise to deferred income tax assets and liabilities:

As a result of acquisitions and business combinations during 2009 and 2008 the Group
recognized a net deferred tax liability of $35 million and $891 million, respectively. Also, in
2009, the Group finalized purchase price allocation related to prior year acquisitions which
resulted in a $140 million decrease of deferred tax liability.

As of December 31, 2009, retained earnings of foreign subsidiaries included $17,261 million for
which deferred taxation has not been provided because remittance of the earnings has been
indefinitely postponed through reinvestment and, as a result, such amounts are considered to be
indefinitely invested. It is not practicable to estimate the amount of additional taxes that might
be payable on such undistributed earnings.

In accordance with ASC No. 830 (former SFAS No. 52, Foreign currency translation) and ASC No. 740
(former SFAS No. 109, Accounting for Income Taxes) deferred tax assets and liabilities are not
recognized for the changes in exchange rate effects resulting from the translation of transactions
and balances from the Russian rubles to the US dollar using historical exchange rates. Also, in
accordance with ASC No. 740, no deferred tax assets or liabilities are recognized for the effects
of the related statutory indexation of property, plant and equipment.

Based upon the levels of historical taxable income and projections for future taxable income over
the periods in which the deferred income tax assets are deductible, management believes it is more
likely than not that Group companies will realize the benefits of the deductible temporary
differences and loss carry forwards, net of existing valuation allowances as of December 31, 2009
and 2008.

As of December 31, 2009, the Group had operating loss carry forwards of $2,273 million of which
$757 million expire during 2010, $82 million expire during 2011, $196 million expire during 2012,
$322 million expire during 2013, $58 million expire during 2014, $58 million expire during 2015, $9
million expire during 2016, $2 million expire during 2017, $12 million expire during 2018, $31
million expire during 2019, $1 million expire during 2020, $67 million expire during 2026, $77
million expire during 2027, $202 million expire during 2028, $2 million expire during 2035 and $397
million have an indefinite carry forward.

Note 13. Pension benefits

The Company sponsors a postretirement benefits program. The primary component of the post
employment and post retirement benefits program is a defined benefit pension plan that covers the
majority of the Groups employees. This plan is administered by a non-state pension fund,
LUKOIL-GARANT, and provides pension benefits primarily based on years of service and final
remuneration levels. The Company also provides several long-term employee benefits such as
death-in-service benefit and lump-sum payments upon retirement of a defined benefit nature and
other defined benefits to certain old age and disabled pensioners who have not vested any pensions
under the pension plan.

The Companys pension plan primarily consists of a defined benefit plan enabling employees to
contribute a portion of their salary to the plan and at retirement to receive a lump sum amount
from the Company equal to all past contributions made by the employee up to 2% (prior to 2009 
7%) of their annual salary. Employees also have the right to receive upon retirement the benefits
accumulated under the previous pension plan that was replaced in December 2003. These benefits have
been fixed and included in the benefit obligation as of December 31, 2009 and 2008. The amount was
determined primarily based on a formula including past pensionable service and relative salaries as
of December 31, 2003.

The Company uses December 31 as the measurement date for its post employment and post retirement
benefits program. An independent actuary has assessed the benefit obligations as of December 31,
2009 and 2008.

The following table provides information about the benefit obligations and plan assets as of
December 31, 2009 and 2008. The benefit obligations below represent the projected benefit
obligation of the pension plan.

2009

2008

Benefit obligations

Benefit obligations as of January 1

288

328

Effect of exchange rate changes

(7

)

(56

)

Service cost

17

22

Interest cost

23

19

Plan amendments

6

21

Actuarial gain

(3

)

(5

)

Acquisitions

8

1

Benefits paid

(30

)

(42

)

Curtailment gain

(11

)



Benefit obligations as of December 31

291

288

Plan assets

Fair value of plan assets as of January 1

88

108

Effect of exchange rate changes

(1

)

(18

)

Return on plan assets

12

6

Employer contributions

45

35

Divestiture

(6

)

(1

)

Benefits paid

(30

)

(42

)

Fair value of plan assets as of December 31

108

88

Funded status

(183

)

(200

)

Amounts recognized in the consolidated balance sheet as of December 31,
2009 and 2008

Accrued benefit liabilities included in Other long-term liabilities

(143

)

(164

)

Accrued benefit liabilities included in Other current liabilities

(40

)

(36

)

Weighted average assumptions used to determine benefit obligations as of December 31, 2009 and
2008:

Weighted average assumptions used to determine net periodic benefit costs for the year ended
December 31, 2009 and 2008:

2009

2008

Discount rate

9.00

%

6.34

%

Rate of compensation increase

8.61

%

8.12

%

Expected rate of return on plan assets

10.89

%

10.49

%

Included in accumulated other comprehensive loss as of December 31, 2009 and 2008, are the
following before-tax amounts that have not yet been recognized in net periodic benefit cost:

2009

2008

Unamortized prior service cost

96

92

Unrecognized actuarial gain

(10

)

(5

)

Total costs

86

87

Amounts recognized in other comprehensive loss during the year ended December 31, 2009 and
2008:

2009

2008

Additional gain arising during the period

(5

)

(1

)

Additional prior service cost from plan amendment

6

21

Re-classified prior service cost amortization

(2

)

(11

)

Net amount recognized for the period

(1

)

9

The real returns on bonds and equities are based on what is observed in the international
markets over extended periods of time. In the calculation of the expected return on assets no use
is made of the historical returns LUKOIL-GARANT has achieved.

In addition to the plan assets, LUKOIL-GARANT holds assets in the form of an insurance reserve. The
purpose of this insurance reserve is to satisfy pension obligations should the plan assets not be
sufficient to meet pension obligations. The Groups contributions to the pension plan are
determined without considering the assets in the insurance reserve.

The plans are funded on a discretionary basis through a solidarity account, which is held in trust
with LUKOIL-GARANT. LUKOIL-GARANT does not allocate separately identifiable assets to the Group or
its other third party clients. All funds of plan assets and other individual pension accounts are
managed as a pool of investments.

The asset allocation of the investment portfolio maintained by LUKOIL-GARANT for the Group and its
clients was as follows:

As of December

As of December

Type of assets

31,2009

31,2008

Promissory notes of Russian issuers

3

%

6

%

Russian corporate bonds

25

%

36

%

Russian municipal bonds

4

%

2

%

Bank deposits

42

%

22

%

Equity securities of Russian issuers

8

%

10

%

Shares of OAO LUKOIL

2

%

2

%

Shares in investment funds

14

%

20

%

Other assets

2

%

2

%

100

%

100

%

The investment strategy employed by LUKOIL-GARANT includes an overall goal to attain a maximum
investment return, while guaranteeing the principal amount invested. The strategy is to invest with
a medium-term perspective while maintaining a level of liquidity through proper allocation of
investment assets. Investment policies include rules and limitations to avoid concentrations of
investments.

The investment portfolio is primarily comprised of investments: bank deposits, securities with
fixed yield and equity securities. The securities with fixed yield include mainly high yield
corporate bonds and promissory notes of banks with low and medium risk ratings. Maturities range
from one to three years.

Components of net periodic benefit cost were as follows:

Year ended

Year ended

Year ended

December 31, 2009

December 31, 2008

December 31, 2007

Service cost

17

22

15

Interest cost

23

19

16

Less expected return on plan assets

(10

)

(11

)

(9

)

Amortization of prior service cost

2

11

8

Actuarial gain





(1

)

Curtailment gain

(11

)





Total net periodic benefit cost

21

41

29

Total employer contributions for 2010 are expected to be $40 million. An amount of $13 million
before-tax is included in other comprehensive income and expected to be recognized in the net
periodic benefit cost in 2010.

The following benefit payments, which reflect expected future services, as appropriate, are
expected to be paid:

Authorized and issued common stock, par value of 0.025 Russian rubles each

850,563

850,563

Common stock held by subsidiaries, not considered as outstanding

(82

)

(82

)

Treasury stock

(3,836

)

(3,836

)

Outstanding common stock

846,645

846,645

Dividends and dividend limitations

Profits available for distribution to common stockholders in respect of any reporting period are
determined by reference to the statutory financial statements of the Company prepared in accordance
with the laws of the Russian Federation and denominated in Russian rubles. Under Russian Law,
dividends are limited to the net profits of the reporting year as set out in the statutory
financial statements of the Company. These laws and other legislative acts governing the rights of
shareholders to receive dividends are subject to various interpretations.

The Companys net profits were 45,148 million Russian rubles, 66,926 million Russian rubles and
64,917 million Russian rubles respectively for 2009, 2008 and 2007, pursuant to the statutory
financial statements, which at the US dollar exchange rates as of December 31, 2009, 2008 and 2007,
amounted to $1,493 million, $2,278 million and $2,645 million, respectively.

At the annual stockholders meeting on June 25, 2009, dividends were declared for 2008 in the
amount of 50.00 Russian rubles per common share, which at the date of the meeting was equivalent to
$1.61.

At the annual stockholders meeting on June 26, 2008, dividends were declared for 2007 in the
amount of 42.00 Russian rubles per common share, which at the date of the meeting was equivalent to
$1.78.

At the annual stockholders meeting on June 28, 2007, dividends were declared for 2006, in the
amount of 38 Russian rubles per common share, which at the date of the decision was equivalent to
$1.47.

Earnings per share

The weighted average number of outstanding common shares was 846,646 thousand shares, 840,108
thousand shares and 828,501 thousand shares for years ended December 31, 2009, 2008 and 2007,
respectively. There is no potential dilution in earnings available to common stockholders and as
such diluted earnings per share are not disclosed.

Note 15. Financial and derivative instruments

Fair value

The fair values of cash and cash equivalents, current accounts and notes receivable, long-term
receivables and liquid securities are approximately equal to their value as disclosed in the
consolidated financial statements. The fair value of long-term receivables was determined by
discounting with estimated market interest rates for similar financing arrangements.

The fair value of long-term debt differs from the amount disclosed in the consolidated financial
statements. The estimated fair value of long-term debt as of December 31, 2009 and 2008 was $9,976
million and $5,425 million, respectively, as a result of discounting using estimated market
interest rates for similar financing arrangements. These amounts include all future cash outflows
associated with the long-term debt repayments, including the current portion and interest. Market
interest rates mean the rates of raising long-term debt by companies with a similar credit rating
for similar tenors, repayment schedules and similar other main terms. During the year ended
December 31, 2009, the Group did not have significant transactions or events that would result in
nonfinancial assets and liabilities measured at fair value on a nonrecurring basis.

Derivative instruments

The Group uses financial and commodity-based derivative contracts to manage exposures to
fluctuations in foreign currency exchange rates, commodity prices, or to exploit market
opportunities. Since the Group is not currently using ASC Nos. 220, 310, 440 and 815 (former SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activity) hedge accounting, all gains
and losses, realized or unrealized, from derivative contracts have been recognized in the
consolidated income statement.

ASC No. 815 requires purchase and sales contracts for commodities that are readily convertible to
cash (e.g., crude oil, natural gas and gasoline) to be recorded on the balance sheet as derivatives
unless the contracts are for quantities the Group expects to use or sell over a reasonable period
in the normal course of business (i.e., contracts eligible for the normal purchases and normal
sales exception). The Group does apply the normal purchases and normal sales exception to certain
long-term contracts to sell oil products. This normal purchases and normal sales exception is
applied to eligible crude oil and refined product commodity purchase and sales contracts; however,
the Group may elect not to apply this exception (e.g., when another derivative instrument will be
used to mitigate the risk of the purchase or sale contract but hedge accounting will not be
applied, in which case both the purchase or sales contract and the derivative contract mitigating
the resulting risk will be recorded on the balance sheet at fair value).

The fair value hierarchy for the Groups derivative assets and liabilities accounted for at fair
value on a recurring basis was:

As of December 31, 2009

As of December 31, 2008

Level 1

Level 2

Level 3

Total

Level 1

Level 2

Level 3

Total

Assets

Commodity derivatives



1,065



1,065



1,995



1,995

Total assets



1,065



1,065



1,995



1,995

Liabilities

Commodity derivatives



(1,110

)



(1,110

)



(1,655

)



(1,655

)

Total liabilities



(1,110

)



(1,110

)



(1,655

)



(1,655

)

Net (liabilities) assets



(45

)



(45

)



340



340

The derivative values above are based on an analysis of each contract as the fundamental unit
of account as required by ASC No. 820; therefore, derivative assets and liabilities with the same
counterparty are not reflected net where the legal right of offset exists. Gains or losses from
contracts in one level may be offset by gains or losses on contracts in another level or by changes
in values of physical contracts or positions that are not reflected in the table above.

The Group operates in the worldwide crude oil, refined product, natural gas and natural gas liquids
markets and is exposed to fluctuations in the prices for these commodities. These fluctuations can
affect the Groups revenues as well as the cost of operating, investing and financing activities.
Generally, the Groups policy is to remain exposed to the market prices of commodities. However,
the Group uses futures, forwards, swaps and options in various markets to balance physical systems,
meet customer needs, manage price exposures on specific transactions, and do a limited, immaterial
amount of trading not directly related to the Groups physical business. These activities may move
the Groups profile away from market average prices.

The fair value of commodity derivative assets and liabilities as of December 31, 2009 was:

As of December31, 2009

Assets

Accounts receivable

1,065

Liabilities

Accounts payable

1,110

Hedge accounting has not been used for items in the table.

As required under ASC No. 815 the amounts shown in the preceding table are presented gross
(i.e., without netting assets and liabilities with the same counterparty where the right of offset
and intent to net exist). Derivative assets and liabilities resulting from eligible commodity
contracts have been netted in the consolidated balance sheet and are recorded as accounts
receivable in the amount of $59 million and accounts payable in the amount of $104 million.

The gains and losses from commodity derivatives were included in the consolidated income statements
in Cost of purchased crude oil, gas and products and for the years ended December 31, 2009 and
2008 were in total amount of net loss of $781 million (of which realized losses were $406 million
and unrealized losses were $375 million) and net income of $902 million (of which realized gain was
$502 million and unrealized gain was $400 million), respectively.

As of December 31, 2009, the net position of outstanding commodity derivative contracts, primarily
to manage price exposure on underlying operations, was not significant.

Currency exchange rate derivative contracts

The Group has foreign currency exchange rate risk resulting from its international operations. The
Group does not comprehensively hedge the exposure to currency rate changes, although the Group
selectively hedges certain foreign currency exchange rate exposures, such as firm commitments for
capital projects or local currency tax payments and dividends.

The fair value of foreign currency derivatives assets and liabilities open at December 31, 2009 was
not significant.

The impact from foreign currency derivatives during the year ended December 31, 2009 on the
consolidated income statement was not significant. The net position of outstanding foreign currency
swap contracts as of December 31, 2009 also was not significant.

The Groups financial instruments that are potentially exposed to concentrations of credit risk
consist primarily of cash equivalents, over-the-counter derivative contracts and trade receivables.
Cash equivalents are placed in high-quality commercial paper, money market funds and time deposits
with major international banks and financial institutions.

The credit risk from the Groups over-the-counter derivative contracts, such as forwards and swaps,
derives from the counterparty to the transaction, typically a major bank or financial institution.
Individual counterparty exposure is managed within predetermined credit limits and includes the use
of cash-call margins when appropriate, thereby reducing the risk of significant non-performance.
The Group also uses futures contracts, but futures have a negligible credit risk because they are
traded on the New York Mercantile Exchange or the ICE Futures.

Certain of the Groups derivative instruments contain provisions that require the Group to post
collateral if the derivative exposure exceeds a threshold amount. The Group has contracts with
fixed threshold amounts and other contracts with variable threshold amounts that are contingent on
the Groups credit rating. The variable threshold amounts typically decline for lower credit
ratings, while both the variable and fixed threshold amounts typically revert to zero if the Group
falls below investment grade. Cash is the primary collateral in all contracts; however, many
contracts also permit the Group to post letters of credit as collateral.

There were no derivative instruments with such credit-risk-related contingent features that were in
a liability position on December 31, 2009. The Group posted $21 million in collateral in the normal
course of business for the over-the-counter derivatives. If the Groups credit rating were lowered
one level from its BBB- rating (per Standard and Poors) on December 31, 2009, and it would be
below investment grade, the Group would be required to post additional collateral of $5 million to
the Groups counterparties for the over-the-counter derivatives, either with cash or letters of
credit. The maximum additional collateral based on the lowest downgrade would be $14 million in
total.

Note 16. Business combinations

During 2009, a Group company acquired the remaining 25.2% of share capital of OAO RITEK (RITEK)
for $235 million, thereby increasing the Groups share to 100%. RITEK is a crude oil producing
company operating in European Russia and Western Siberia.

In the first quarter of 2009, the Group acquired 100% interests in OOO Smolenskneftesnab, OOO IRT
Investment, OOO PM Invest and OOO Retaier House for $238 million. These are holding companies,
which between them own 96 petrol stations and plots of land in Moscow, the Moscow region and other
regions of central European Russia. This acquisition was made in order to expand the Groups
presence on the most advantageous retail market in the Russian Federation. The Group allocated $165
million to goodwill, $113 million to property, plant and equipment, $15 million to other assets, $8
million to deferred tax liability and $47 million to other liabilities. The value of property,
plant and equipment was determined by an independent appraiser.

In the fourth quarter of 2008, the Group acquired 100% interests in ZAO Association Grand and OOO
Mega Oil M for $493 million. ZAO Association Grand and OOO Mega Oil M are holding companies, owning
181 petrol stations in Moscow, the Moscow region and other regions of central European Russia. This
acquisition was made in order to expand the Groups presence on the most advantageous retail market
in the Russian Federation. The Group allocated $196 million to goodwill, $334 million to property,
plant and equipment, $46 million to other assets, $14 million to deferred tax liability and $69
million to other liabilities. The value of property, plant and equipment was determined by an
independent appraiser.

In March 2008, a Group company entered into an agreement with a related party, whose management and
directors include members of the Groups management and Board of Directors, to acquire a 64.31%
interest in TGK-8 for approximately $2,117 million. The purchase consideration partly consists of
23.55 million shares of common stock of the Company (at a market value of approximately $1,620
million). The transaction was finalized in May 2008. The following table summarizes the determined
fair value of the assets acquired and liabilities assumed of TGK-8 at the date of acquisition. The
value of property, plant and equipment was determined by an independent appraiser.

Cash and short-term investments

724

Other current assets

266

Property, plant and equipment

2,092

Other non-current assets

319

Total assets acquired

3,401

Current liabilities

(196

)

Non-current deferred tax liabilities

(357

)

Long-term debt

(149

)

Minority interest

(582

)

Total liabilities assumed

(1,284

)

Net assets acquired

2,117

From May to December 2008, a Group company acquired additional interests in TGK-8 for a total
of $1,075 million. These acquisitions increased the Groups ownership to 95.53%. As a result of
this additional acquisition the Group recognized property, plant and equipment and a deferred tax
liability amounting to $802 million and $192 million, respectively. From January to June 2009, a
Group company acquired the remaining 4.47% of share capital of TGK-8 for approximately $127
million. The acquisition increased the Groups ownership to 100%. TGK-8 is a power generating
company which owns power plants located in the Astrakhan, Volgograd and Rostov regions, the
Krasnodar and Stavropol Districts, and the Republic of Dagestan of the Russian Federation. This
acquisition is made in accordance with the Companys plans to develop its electric power business.

In July 2008, a Group company signed an agreement to acquire a 100% interest in the Akpet group for
$555 million. The transaction was finalized in November 2008. Based on the agreement there were
three payments of purchase consideration: the first payment in the amount of $250 million was paid
at the date of finalization; second and third deferred payments were paid in April and October
2009. The Akpet group operated 689 petrol filling stations on the basis of dealer agreements and
owned eight refined product terminals, five LNG storage tanks, three jet fuel terminals and a
lubricant production plant in Turkey. The Group allocated $114 million to goodwill, $271 million to
intangible assets and $241 million to property, plant and equipment. The value of intangible assets
and property, plant and equipment was determined by an independent appraiser.

In March 2008, a Group company entered into an agreement to acquire 75 petrol stations and storage
facilities in Bulgaria for approximately $367 million. The transaction was finalized in the second
quarter of 2008. The Group determined the fair value of assets acquired and as a result recognized
property, plant and equipment of $367 million.

These business combinations did not have a material impact on the Groups consolidated operations
for the years ended December 31, 2009 and 2008. Therefore, no pro-forma income statement
information has been provided.

The Group and ConocoPhillips have a joint venture NMNG which develops oil reserves in the
Timan-Pechora region of the Russian Federation. The Group and ConocoPhillips have equal voting
rights over the joint ventures activity and effective ownership interests of 70% and 30%,
respectively.

The Group determined that NMNG is a variable interest entity as the Groups voting rights are not
proportionate to its ownership rights and all of NMNGs activities are conducted on behalf of the
Group and ConocoPhillips, its related party. The Group is considered to be the primary beneficiary
and has consolidated NMNG.

NMNGs total assets were approximately $5.9 billion and $7.1 billion as of December 31, 2009 and
2008, respectively.

The Group and ConocoPhillips agreed to provide financing to NMNG by means of long-term loans in
proportion to their effective ownership interests. These loans mature from 2035 to 2038, with the
option to be extended for a further 35 years with the agreement of both parties. As of December 31,
2009, borrowings under these agreements bear fixed interest in the range of 6.8% to 8.2% per annum.

As of December 31, 2009, the amount outstanding to ConocoPhillips from NMNG was $1,660 million,
which consists of a number of loans with a weighted-average interest rate of 7.79% per annum. This
amount is presented within Long-term loans and borrowings from related parties.

Note 18. Financial guarantees

The Group has entered into various guarantee arrangements. These arrangements were entered into in
order to optimize affiliated companies financing terms. The undiscounted maximum amount of
potential future payments for the guarantees issued in favour of equity companies was $50 million
and $161 million as of December 31, 2009 and 2008, respectively.

Note 19. Commitments and contingencies

Capital expenditure, exploration and investment programs

The Group owns and operates refineries in Bulgaria (LUKOIL Neftochim Bourgas AD) and Romania
(Petrotel-LUKOIL S.A.). As a result of Bulgaria and Romania joining the European Union in 2007,
LUKOIL Neftochim Bourgas AD and Petrotel-LUKOIL S.A. are required to upgrade their refining plants
to comply with the requirements of European Union legislation in relation to the quality of
produced petroleum products and environmental protection. These requirements are stricter than
those which previously existed under Bulgarian and Romanian legislation. The Group estimates the
amount of future capital commitment required to upgrade LUKOIL Neftochim Bourgas AD and
Petrotel-LUKOIL S.A. to be approximately $49 million and $44 million, respectively.

Under the terms of existing exploration and production license agreements in Russia the Group has
to fulfill certain operations: oil and gas exploration, wells drilling, fields development, etc.,
and the Group also has commitments to reach a defined level of extraction on the fields. Management
believes that the Groups approved annual capital expenditure budgets fully cover all the
requirements of the described license obligations.

Group companies have commitments for capital expenditure contributions in the amount of $565
million related to various production sharing agreements over the next 28 years.

The Company has signed a three-year agreement for drilling services with OOO Eurasia Drilling
Company. The volume of these services is based on the Groups capital construction program, which
is re-evaluated on an annual basis. The Group estimates the amount of capital commitment under this
agreement for 2010 to be approximately $610 million.

The Company has signed a strategic agreement for the ongoing provision of construction, engineering
and technical services with ZAO Globalstroy-Engineering. The volume of these services is based on
the Groups capital construction program, which is re-evaluated on an annual basis. The Group
estimates the amount of capital commitment under this agreement for 2010 to be approximately $126
million.

The Group has a commitment to purchase equipment for modernization of its petrochemical refinery
Karpatnaftochim Ltd., located in Ukraine, during next two years in the amount of $55 million.

The Group has a commitment to execute the capital construction program of TGK-8 (refer to Note 16.
Business combinations) and under the terms of this program power plants with total capacity of 890
MW should be constructed. Currently the Group is approving certain amendments to the capital
construction program, which included its extension by the end of 2013. As of December 31, 2009, the
Group estimates the amount of this commitment to be approximately $944 million.

Operating lease obligations

Group companies have commitments of $974 million primarily for the lease of vessels and petroleum
distribution outlets. Operating lease expenses were $185 million and $170 million during the years
ended December 31, 2009 and 2008, respectively. Commitments for minimum rentals under these leases
as of December 31, 2009 are as follows:

As of December

31, 2009

2010

276

2011

172

2012

135

2013

104

2014

93

beyond

194

Insurance

The insurance industry in the Russian Federation and certain other areas where the Group has
operations is in the course of development. Management believes that the Group has adequate
property damage coverage for its main production assets. In respect of third party liability for
property and environmental damage arising from accidents on Group property or relating to Group
operations, the Group has insurance coverage that is generally higher than insurance limits set by
the local legal requirements. Management believes that the Group has adequate insurance coverage of
the risks, which could have a material effect on the Groups operations and financial position.

Environmental liabilities

Group companies and their predecessor entities have operated in the Russian Federation and other
countries for many years and, within certain parts of the operations, environmental related
problems have developed. Environmental regulations are currently under consideration in the Russian
Federation and other areas where the Group has operations. Group companies routinely assess and
evaluate their obligations in response to new and changing legislation.

As liabilities in respect of the Groups environmental obligations are able to be determined, they
are charged against income. The likelihood and amount of liabilities relating to environmental
obligations under proposed or any future legislation cannot be reasonably estimated at present and
could become material. Under existing legislation, however, management believes that there are no
significant unrecorded liabilities or contingencies, which could have a materially adverse effect
on the operating results or financial position of the Group.

Social assets

Certain Group companies contribute to Government sponsored programs, the maintenance of local
infrastructure and the welfare of their employees within the Russian Federation and elsewhere. Such
contributions include assistance with the construction, development and maintenance of housing,
hospitals and transport services, recreation and other social needs. The funding of such assistance
is periodically determined by management and is appropriately capitalized or expensed as incurred.

Taxation environment

The taxation systems in the Russian Federation and other emerging markets where Group companies
operate are relatively new and are characterized by numerous taxes and frequently changing
legislation, which is often unclear, contradictory, and subject to interpretation. Often, differing
interpretations exist among different tax authorities within the same jurisdictions and among
taxing authorities in different jurisdictions. Taxes are subject to review and investigation by a
number of authorities, which are enabled by law to impose severe fines, penalties and interest
charges. In the Russian Federation a tax year remains open for review by the tax authorities during
the three subsequent calendar years; however, under certain circumstances a tax year may remain
open longer. Recent events within the Russian Federation suggest that the tax authorities are
taking a more assertive position in their interpretation and enforcement of tax legislation. Such
factors may create taxation risks in the Russian Federation and other emerging markets where Group
companies operate substantially more significant than those in other countries where taxation
regimes have been subject to development and clarification over long periods.

The tax authorities in each region may have a different interpretation of similar taxation issues
which may result in taxation issues successfully defended by the Group in one region being
unsuccessful in another region. There is some direction provided from the central authority based
in Moscow on particular taxation issues.

The Group has implemented tax planning and management strategies based on existing legislation at
the time of implementation. The Group is subject to tax authority audits on an ongoing basis, as is
normal in the Russian environment and other republics of the former Soviet Union, and, at times,
the authorities have attempted to impose additional significant taxes on the Group. Management
believes that it has adequately met and provided for tax liabilities based on its interpretation of
existing tax legislation. However, the relevant tax authorities may have differing interpretations
and the effects on the financial statements, if the authorities were successful in enforcing their
interpretations, could be significant.

Litigation and claims

On November 27, 2001, Archangel Diamond Corporation (ADC), a Canadian diamond development
company, filed a lawsuit in the District Court of Denver, Colorado against OAO
Archangelskgeoldobycha (AGD), a Group company, and the Company (together the Defendants). ADC
alleged that the Defendants interfered with the transfer of a diamond exploration license to
Almazny Bereg, a joint venture between ADC and AGD. ADC claimed total damages of approximately $4.8
billion, including compensatory damages of $1.2 billion and punitive damages of $3.6 billion. On
October 15, 2002, the District Court dismissed the lawsuit for lack of personal jurisdiction.

This ruling was upheld by the Colorado Court of Appeals on March 25, 2004. On November 21, 2005,
the Colorado Supreme Court affirmed the lower courts ruling that no specific jurisdiction exists
over the Defendants. By virtue of this finding, AGD (the holder of the diamond exploration license)
was dismissed from the lawsuit. The Supreme Court found, however, that the trial court made a
procedural error by failing to hold an evidentiary hearing before making its ruling concerning
general jurisdiction regarding the Company, which is whether the Company had systematic and
continuous contacts in the State of Colorado at the time the lawsuit was filed. In a modified
opinion dated December 19, 2005, the Colorado Supreme Court remanded the case to the Colorado Court
of Appeals (instead of the District Court) to consider whether the lawsuit should have been
dismissed on alternative grounds (i.e., forum non conveniens). On June 29, 2006, the Colorado Court
of Appeals declined to dismiss the case based on forum non conveniens. The Company filed a petition
for certiorari on August 28, 2006, asking the Colorado Supreme Court to review this decision. On
March 5, 2007, the Colorado Supreme Court remanded the case to the District Court. On June 11,
2007, the District Court ruled it would conduct an evidentiary hearing on the issue of whether the
Company is subject to general personal jurisdiction in the State of Colorado. Discovery regarding
jurisdiction was commenced. On June 26, 2009, three creditors of ADC filed an Involuntary
Bankruptcy Petition putting ADC into bankruptcy. ADC ultimately confirmed entry of an Order For
Relief and the matter was converted to a Chapter 11 Case by order dated September 29, 2009. On
November 25, 2009, after adding a claim, ADC removed the case from the Colorado District Court to
the US Bankruptcy Court. On December 22, 2009, the Company filed a motion seeking to have the case
remanded to the Colorado District Court. On December 31, 2009, before there was a ruling on the
motion seeking remand ADC filed a motion seeking withdrawal of the reference from the bankruptcy
and the case be heard by US District Court. On February 3, 2010, the US Bankruptcy Court ordered
the Motion For Withdrawal Of The Reference be transferred to the US District Court for further
action. All pending motions as well as discovery are stayed pending further order of the Court.
Management plans to vigorously defend the matter. Management does not believe that the ultimate
resolution of this matter will have a material adverse effect on the Groups financial condition.

In 2008 and 2009, the Federal Anti-monopoly Service of the Russian Federation (FAS of Russia)
issued two decisions against major Russian oil companies, including the Company and the Groups
refinery plants alleging abuse of their dominant position in the oil products wholesale market of
the Russian Federation.

The Moscow Arbitration Court combined all refinery plants appeals against the first decision. The
next appeal hearing was scheduled for April 8, 2010.

The second decision of FAS of Russia was appealed by the refinery plants in their local courts. On
February 8, 2010, the Arbitration Court of Nizhi Novgorod Region satisfied the request of OOO
LUKOIL-Nizhnegorodnefteorgsintez to recognize as illegal the decisions of FAS of Russia dated
September 10, 2009 and the resolution to impose fines in the amount of $80 million. The appeals of
the other refinery plants are currently suspended.

In the second half of 2008 and first half of 2009, the FAS of Russia filed claims against several
Group companies in relation to violation of the anti-monopoly regulation. The companies were
accused of violations primarily involving abuse of their dominant market position via setting
monopolistically high retail prices in coordination with other market participants. These claims
are being appealed in the courts.

The total amount of penalties assessed under the administrative law for the violation of
anti-monopoly regulation by the Group in 2008-2009 is $290 million. Management believes that the
Group complied with all regulatory and legal requirements and, consequently, believes that the
ultimate resolution of the antimonopoly claims will lead to cancellation or significant reduction
of these penalties and will not have a material adverse impact on the Groups operating results or
financial condition.

The Group is involved in various other claims and legal proceedings arising in the normal course of
business. While these claims may seek substantial damages against the Group and are subject to
uncertainty inherent in any litigation, management does not believe that the ultimate resolution of
such matters will have a material adverse impact on the Groups operating results or financial
condition.

Note 20. Related party transactions

In the rapidly developing business environment in the Russian Federation, companies and individuals
have frequently used nominees and other forms of intermediary companies in transactions. The senior
management of the Company believes that the Group has appropriate procedures in place to identify
and properly disclose transactions with related parties in this environment and has disclosed all
of the relationships identified which it deemed to be significant. Related party sales and
purchases of oil and oil products were primarily to and from affiliated companies and the Companys
shareholder ConocoPhillips. Related party processing services were provided by affiliated
refineries. Insurance services were provided by the related parties, whose management and directors
include members of the Groups management.

Below are related party transactions not disclosed elsewhere in the financial statements. Refer
also to Notes 3, 4, 7, 10, 11, 13, 16, 17, 18 and 21 for other transactions with related parties.

Sales of oil and oil products to related parties were $1,152 million, $436 million and $652 million
for the years ended December 31, 2009, 2008 and 2007, respectively.

Other sales to related parties were $69 million, $86 million and $77 million for the years ended
December 31, 2009, 2008 and 2007, respectively.

Purchases of oil and oil products from related parties were $862 million, $1,891 million and $1,363
million for the years ended December 31, 2009, 2008 and 2007, respectively.

Purchases of processing services from related parties were $539 million, nil and nil for the years
ended December 31, 2009, 2008 and 2007, respectively.

Purchases of insurance services from related parties were nil, $93 million and $143 million during
the years ended December 31, 2009, 2008 and 2007, respectively.

Other purchases from related parties were $28 million, $33 million and $26 million for the years
ended December 31, 2009, 2008 and 2007, respectively.

Amounts receivable from related parties, including loans and advances, were $591 million and $248
million as of December 31, 2009 and 2008, respectively. Amounts payable to related parties were $97
million and $36 million as of December 31, 2009 and 2008, respectively.

Note 21. Compensation plan

During the period from 2007 to 2009, the Company had a compensation plan available to certain
members of management, which is based on assigned shares and provides compensation consisting of
two parts.

The first part represented annual bonuses that are based on the number of assigned shares and
amount of dividend per share. The payment of these bonuses is contingent on the Group meeting
certain financial KPIs in each financial year. The second is based upon the Companys common stock
appreciation from 2007 to 2009, with rights vested in December 2009. The number of assigned shares
is approximately 15.5 million shares. For the first part of the share plan the Group recognizes a
liability based on expected dividends and number of assigned shares.

The second part of the share plan is classified as equity and the grant date fair value of the plan
is estimated using the Black-Scholes-Merton option-pricing model. Related to this plan the Group
recorded $105 million, $134 million and $125 million of compensation expense during the years ended
December 31, 2009, 2008 and 2007, respectively, of which $20 million, $103 million and $103 million
are recognized as an increase in additional paid-in capital in respective periods. Because of
unfavorable market situation the conditions for exercising the second part of this share plan were
not met therefore no payments or share transfers to employees took place.

In December 2009, the Company introduced a new compensation plan to certain members of management
for the period from 2010 to 2012. Its conditions are similar to the conditions of the previous
compensation plan. The number of assigned shares is approximately 17.3 million shares. The Group is
currently finalizing the calculation of the grant date fair value of the new plan.

Note 22. Segment information

Presented below is information about the Groups operating and geographical segments for the years
ended December 31, 2009, 2008 and 2007, in accordance with ASC No. 280 (former SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information).

The Group has four operating segments  exploration and production; refining, marketing and
distribution; chemicals and other business segments. These segments have been determined based on
the nature of their operations. Management on a regular basis assesses the performance of these
operating segments. The exploration and production segment explores for, develops and produces
primarily crude oil. The refining, marketing and distribution segment processes crude oil into
refined products and purchases, sells and transports crude oil and refined petroleum products. The
chemicals segment refines and sells chemical products. Activities of the other business operating
segment include power generation business and development of businesses beyond the Groups
traditional operations.

Geographical segments have been determined based on the area of operations and include three
segments. They are Western Siberia, European Russia and International.

The Groups international sales to third parties include sales in Switzerland of $37,724 million,
$47,066 million and $35,868 million for the years ended December 31, 2009, 2008 and 2007,
respectively. The Groups international sales to third parties include sales in the USA of $8,144
million, $12,171 million and $11,481 million for the years ended December 31, 2009, 2008 and 2007,
respectively. These amounts are attributed to individual countries based on the jurisdiction of
subsidiaries making the sale.

Note 23. Subsequent events

In accordance with the requirements of ASC No. 855, Subsequent events, the Group evaluated
subsequent events through the date the financial statements were available to be issued. Therefore
subsequent events were evaluated by the Group up to March 19, 2010.

In January 2010, the Company signed a development and production agreement at West Qurna-2 field
located in the south of Iraq. The parties to the agreement are: Iraqs state-owned South Oil
Company and the contracting consortium formed by the Iraqi state-owned North Oil Company, the
Company and Norways Statoil ASA. The Companys share in the project is 56.25%. As at the day of
the agreement the Group has a commitment in the amount of approximately $281 million. The West
Qurna-2 field has recoverable reserves of about 12.9 billion barrels.

OAO LUKOIL
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)
(Millions of US dollars, except as indicated)

III. Results of operations for oil and gas producing activities

The Groups results of operations for oil and gas producing activities are presented below. In
accordance with ASC No. 932, sales and transfers to Group companies are based on market prices.
Income taxes are based on statutory rates. The results of operations exclude corporate overhead and
interest costs.

OAO LUKOIL
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)
(Millions of US dollars, except as indicated)

IV. Reserve quantity information

Proved reserves are the estimated quantities of oil and gas reserves which geological and
engineering data demonstrate will be recoverable with reasonable certainty in future years from
known reservoirs under existing economic and operating conditions. In accordance with ASC No. 932
existing economic and operating conditions are based on the 12-months average price (for the year
2009) or year-end price (for the periods before 2009) and the year-end costs. Proved reserves do
not include additional quantities of oil and gas reserves that may result from applying secondary
or tertiary recovery techniques not yet tested and determined to be economic.

Proved developed reserves are the quantities of proved reserves expected to be recovered through
existing wells with existing equipment and operating methods.

Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates
of reserves are inherently imprecise, require the application of judgment and are subject to change
as additional information becomes available.

Management has included within proved reserves significant quantities which the Group expects to
produce after the expiry dates of certain of its current production licenses in the Russian
Federation. The Subsoil Law of the Russian Federation states that, upon expiration, a license is
subject to renewal at the initiative of the license holder provided that further exploration,
appraisal, production or remediation activities are necessary and provided that the license holder
has not violated the terms of the license. Since the law applies both to newly issued and old
licenses and the Group has currently renewed nearly 50% of its licenses, management believes that
licenses will be renewed upon their expiration for the remainder of the economic life of each
respective field.

In January 2010, the FASB issued ASU No. 2010-03, Extractive activities  Oil and Gas (Topic 932):
Oil and Gas Reserve Estimation and Disclosures. The adoption of ASU No. 2010-03 did not have a
significant impact on the Groups proved reserves and standardized measure of discounted future net
cash flows.

Estimated net proved oil and gas reserves and changes thereto for the years ended December 31,
2009, 2008 and 2007, are shown in the tables set out below.

OAO LUKOIL
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)
(Millions of US dollars, except as indicated)

Group's share

in equity

Millions of barrels

Consolidated subsidiaries

companies

Total

International

Russia

Total

Crude oil

January 1, 2007

410

15,183

15,593

334

15,927

Revisions of previous estimates

2

35

37

(23

)

14

Purchase of hydrocarbons in place*



178

178

(104

)

74

Extensions and discoveries

20

463

483

35

518

Production

(26

)

(668

)

(694

)

(19

)

(713

)

Sales of reserves

(105

)



(105

)



(105

)

December 31, 2007

301

15,191

15,492

223

15,715

Revisions of previous estimates

80

(1,205

)

(1,125

)

1

(1,124

)

Purchase of hydrocarbons in place

17

19

36

5

41

Extensions and discoveries

30

493

523

6

529

Production

(24

)

(660

)

(684

)

(19

)

(703

)

December 31, 2008

404

13,838

14,242

216

14,458

Revisions of previous estimates

(85

)

(636

)

(721

)

15

(706

)

Purchase of hydrocarbons in place



39

39

102

141

Extensions and discoveries

37

503

540



540

Production

(27

)

(673

)

(700

)

(20

)

(720

)

Sales of reserves



(17

)

(17

)



(17

)

December 31, 2009

329

13,054

13,383

313

13,696

Proved developed reserves

December 31, 2007

164

9,715

9,879

180

10,059

December 31, 2008

208

8,806

9,014

156

9,170

December 31, 2009

186

8,442

8,628

199

8,827

* Purchase of hydrocarbons in place for equity companies includes transfers of reserves to the
consolidated group upon those equity companies becoming subject to consolidation.

The minority interest share included in the above total proved reserves was 242 million
barrels, 426 million barrels and 559 million barrels as of December 31, 2009, 2008 and 2007,
respectively. The minority interest share included in the above proved developed reserves was 135
million barrels, 203 million barrels and 228 million barrels as of December 31, 2009, 2008 and
2007, respectively. Substantially all minority interests relate to the reserves in the Russian
Federation.

OAO LUKOIL
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)
(Millions of US dollars, except as indicated)

Group's share

in equity

Billions of cubic feet

Consolidated subsidiaries

companies

Total

International

Russia

Total

Natural gas

January 1, 2007

4,276

22,128

26,404

193

26,597

Revisions of previous estimates

506

550

1,056

(2

)

1,054

Purchase of hydrocarbons in place*



19

19

(14

)

5

Extensions and discoveries

207

630

837

7

844

Production

(87

)

(482

)

(569

)

(10

)

(579

)

December 31, 2007

4,902

22,845

27,747

174

27,921

Revisions of previous estimates

566

(386

)

180

4

184

Purchase of hydrocarbons in place

1,395

4

1,399



1,399

Extensions and discoveries

118

310

428

7

435

Production

(175

)

(500

)

(675

)

(11

)

(686

)

December 31, 2008

6,806

22,273

29,079

174

29,253

Revisions of previous estimates

(294

)

(6,081

)

(6,375

)

(3

)

(6,378

)

Purchase of hydrocarbons in place



13

13

130

143

Extensions and discoveries

294

164

458



458

Production

(175

)

(436

)

(611

)

(15

)

(626

)

December 31, 2009

6,631

15,933

22,564

286

22,850

Proved developed reserves:

December 31, 2007

1,369

6,553

7,922

133

8,055

December 31, 2008

1,912

5,893

7,805

114

7,919

December 31, 2009

2,002

5,636

7,638

157

7,795

* Purchase of hydrocarbons in place for equity companies includes transfers of reserves to the
consolidated group upon those equity companies becoming subject to consolidation.

The minority interest share included in the above total proved reserves was 36 billion cubic
feet, 34 billion cubic feet and 49 billion cubic feet as of December 31, 2009, 2008 and 2007,
respectively. The minority interest share included in the above proved developed reserves was 23
billion cubic feet, 24 billion cubic feet and 30 billion cubic feet as of December 31, 2009, 2008
and 2007, respectively. Substantially all minority interests relate to the reserves in the Russian
Federation.

As a result of changes to development plans and commissioning dates, the Company transferred part
of its gas reserves from the category of proved reserves into lower reserve categories and into
resources. Management believes that these volumes will be returned into the proved reserves
category as their development start date draws nearer or some new technologies are applied.

OAO LUKOIL
Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)
(Millions of US dollars, except as indicated)

V. Standardized measure of discounted future net cash flows

The standardized measure of discounted future net cash flows, related to the above oil and gas
reserves, is calculated in accordance with the requirements of ASC No. 932. Estimated future cash
inflows from production are computed by applying the 12-months average price (for the year 2009) or
year-end price (for the periods before 2009) for oil and gas to year-end quantities of estimated
net proved reserves. Adjustment in this calculation for future price changes is limited to those
required by contractual arrangements in existence at the end of each reporting year. Future
development and production costs are those estimated future expenditures necessary to develop and
produce year-end estimated proved reserves based on year-end cost indices, assuming continuation of
year-end economic conditions. Estimated future income taxes are calculated by applying appropriate
year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are
applied to estimated future pre-tax net cash flows, less the tax bases of related assets.
Discounted future net cash flows have been calculated using a ten percent discount factor.
Discounting requires a year-by-year estimate of when future expenditures will be incurred and when
reserves will be produced.

The information provided in the tables set out below does not represent managements estimate of
the Groups expected future cash flows or of the value of the Groups proved oil and gas reserves.
Estimates of proved reserve quantities are imprecise and change over time as new information
becomes available. Moreover, probable and possible reserves, which may become proved in the future,
are excluded from the calculations. The arbitrary valuation prescribed under ASC No. 932 requires
assumptions as to the timing and amount of future development and production costs. The
calculations should not be relied upon as an indication of the Groups future cash flows or of the
value of its oil and gas reserves.

Total

Groups share

consolidated

in equity

International

Russia

companies

companies

Total

As of December 31, 2009

Future cash inflows

31,025

385,266

416,291

14,816

431,107

Future production and development costs

(18,778

)

(254,811

)

(273,589

)

(7,692

)

(281,281

)

Future income tax expenses

(2,337

)

(22,285

)

(24,622

)

(1,489

)

(26,111

)

Future net cash flows

9,910

108,170

118,080

5,635

123,715

Discount for estimated timing of cash
flows (10% p.a.)

(6,468

)

(66,015

)

(72,483

)

(3,013

)

(75,496

)

Discounted future net cash flows

3,442

42,155

45,597

2,622

48,219

Minority share in discounted future
net cash flows



1,370

1,370



1,370

Included as a part of the $281 billion of future production and development costs are $6.5
billion of future dismantlement, abandonment and rehabilitation costs.

Amended and Restated Certificate of Incorporation (incorporated by reference to Exhibit 3.1
to the Quarterly Report of ConocoPhillips on Form 10-Q for the quarterly period ended June 30,
2008; File No. 001-32395).

3.2

Certificate of Designations of Series A Junior Participating Preferred Stock of
ConocoPhillips (incorporated by reference to Exhibit 3.2 to the Current Report of
ConocoPhillips on Form 8-K filed on August 30, 2002; File No. 000-49987).

3.3

By-Laws of ConocoPhillips, as amended on December 12, 2008 (incorporated by reference to
Exhibit 3.1 to the Current Report of ConocoPhillips on Form 8-K filed on December 12, 2008;
File No. 001-32395).

4.1

Rights agreement, dated as of June 30, 2002, between ConocoPhillips and Mellon Investor
Services LLC, as rights agent, which includes as Exhibit A the form of Certificate of
Designations of Series A Junior Participating Preferred Stock, as Exhibit B the form of Rights
Certificate and as Exhibit C the Summary of Rights to Purchase Preferred Stock (incorporated
by reference to Exhibit 4.1 to the Current Report of ConocoPhillips on Form 8-K filed on
August 30, 2002; File No. 000-49987).

ConocoPhillips and its subsidiaries are parties to several debt instruments under which
the total amount of securities authorized does not exceed 10 percent of the total assets
of ConocoPhillips and its subsidiaries on a consolidated basis. Pursuant to paragraph
4(iii)(A) of Item 601(b) of Regulation S-K, ConocoPhillips agrees to furnish a copy of
such instruments to the SEC upon request.

10.1

Shareholder Agreement, dated September 29, 2004, by and between LUKOIL and ConocoPhillips
(incorporated by reference to Exhibit 99.2 of the Current Report of ConocoPhillips on Form 8-K
filed on September 30, 2004; File No. 333-74798).

10.2

1986 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.11 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).

10.3

1990 Stock Plan of Phillips Petroleum Company (incorporated by reference to Exhibit 10.12 to
the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2002;
File No. 000-49987).

10.4

Annual Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference
to Exhibit 10.13 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.5

Incentive Compensation Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10(g) to the Annual Report of ConocoPhillips Company on Form 10-K for the year
ended December 31, 1999; File No. 1-720).

ConocoPhillips Supplemental Executive Retirement Plan (incorporated by reference to
Exhibit 10.7 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005;
File No. 001-32395).

10.7

Non-Employee Director Retirement Plan of Phillips Petroleum Company (incorporated by
reference to Exhibit 10.18 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2002; File No. 000-49987).

10.8

Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to Exhibit
10.19 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2002;
File No. 000-49987).

10.9

Key Employee Missed Credited Service Retirement Plan of ConocoPhillips (incorporated by
reference to Exhibit 10.10 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).

10.10

Phillips Petroleum Company Stock Plan for Non-Employee Directors (incorporated by reference
to Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.11

ConocoPhillips Key Employee Supplemental Retirement Plan (incorporated by reference to
Exhibit 10.11 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2008; File No. 001-32395).

10.12.1

Defined Contribution Make-Up Plan of ConocoPhillipsTitle I (incorporated by reference to
Exhibit 10.13.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2005; File No. 001-32395).

10.12.2

Defined Contribution Make-Up Plan of ConocoPhillipsTitle II (incorporated by reference to
Exhibit 10.12.2 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2008; File No. 001-32395).

10.13

2002 Omnibus Securities Plan of Phillips Petroleum Company (incorporated by reference to
Exhibit 10.26 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.14

1998 Stock and Performance Incentive Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.27 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.15

1998 Key Employee Stock Performance Plan of ConocoPhillips (incorporated by reference to
Exhibit 10.28 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2002; File No. 000-49987).

10.16

Deferred Compensation Plan for Non-Employee Directors of ConocoPhillips (incorporated by
reference to Exhibit 10.17 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).

ConocoPhillips Form Indemnity Agreement with Directors (incorporated by reference to
Exhibit 10.34 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.18

Rabbi Trust Agreement dated December 17, 1999 (incorporated by reference to Exhibit 10.11 of
the Annual Report of ConocoPhillips Holding Company on Form 10-K for the year ended December
31, 1999; File No. 001-14521).

10.18.1

Amendment to Rabbi Trust Agreement dated February 25, 2002 (incorporated by reference to
Exhibit 10.39.1 to the Annual Report of ConocoPhillips on Form 10-K for the year ended
December 31, 2002; File No. 000-49987).

10.19

ConocoPhillips Directors Charitable Gift Program (incorporated by reference to Exhibit
10.40 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December 31,
2003;
File No. 000-49987).

10.19.1

First and Second Amendments to the ConocoPhillips Directors Charitable Gift Program
(incorporated by reference to Exhibit 10 to the Quarterly Report of ConocoPhillips on Form
10-Q for the quarterly period ended June 30, 2008; File No. 001-32395).

10.20

ConocoPhillips Matching Gift Plan for Directors and Executives (incorporated by reference to
Exhibit 10.41 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2003; File No. 000-49987).

10.21.1

Key Employee Deferred Compensation Plan of ConocoPhillipsTitle I (incorporated by
reference to Exhibit 10.23.1 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2005; File No. 001-32395).

10.21.2

Key Employee Deferred Compensation Plan of ConocoPhillipsTitle II (incorporated by
reference to Exhibit 10.21.2 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2008; File No. 001-32395).

10.22

ConocoPhillips Key Employee Change in Control Severance Plan (incorporated by reference to
Exhibit 10.22 to the Annual Report of ConocoPhillips on Form 10-K for the year ended December
31, 2008; File No. 001-32395).

10.23

ConocoPhillips Executive Severance Plan (incorporated by reference to Exhibit 10.23 to the
Annual Report of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No.
001-32395).

Aircraft Time Sharing Agreement by and between James J. Mulva and ConocoPhillips
(incorporated by reference to Exhibit 10 of the Quarterly Report of ConocoPhillips on Form
10-Q for the quarterly period ended June 30, 2007; File No. 001-32395).

10.26

Form of Stock Option Award Agreement under the ConocoPhillips Stock Option and Stock
Appreciation Rights Program (incorporated by reference to Exhibit 10.26 to the Annual Report
of ConocoPhillips on Form 10-K for the year ended December 31, 2008; File No. 001-32395).

Form of Restricted Stock Unit Award Agreement under the ConocoPhillips Performance Share
Program (incorporated by reference to Exhibit 10.27 to the Annual Report of ConocoPhillips on
Form 10-K for the year ended December 31, 2008; File No. 001-32395).

10.28

Omnibus Amendments to certain ConocoPhillips employee benefit plans, adopted
December 7, 2007 (incorporated by reference to Exhibit 10.30 to the Annual Report of
ConocoPhillips on Form 10-K for the year ended December 31, 2007; File No. 001-32395).

10.29

Letter Agreement between ConocoPhillips and John E. Lowe, dated October 1, 2008
(incorporated by reference to Exhibit 99.1 to the Current Report of ConocoPhillips on Form 8-K
filed on October 1, 2008; File No. 001-32395).

10.30

Annex to Nonqualified Deferred Compensation Arrangements of ConocoPhillips (incorporated by
reference to Exhibit 10.30 to the Annual Report of ConocoPhillips on Form 10-K for the year
ended December 31, 2008; File No. 001-32395).

10.31

2009 Omnibus Stock and Performance Incentive Plan of ConocoPhillips (incorporated by
reference to Appendix A of ConocoPhillips Proxy Statement on Schedule 14A relating to the
2009 Annual Meeting of Shareholders; File No. 001-32395).

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto
duly authorized.